ReoStar Energy CORP - Quarter Report: 2008 June (Form 10-Q)

REOSTAR ENERGY CORP - Form 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

x	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

	For the quarterly period ended June 30, 2008

o	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

	For the transition period from ______________to ______________.

Commission File Number 000-52316

REOSTAR ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

Nevada				20-8428738
(State or other jurisdiction of incorporation or organization)				(I.R.S. Employer Identification No.)

3880 Hulen Street, Suite 500, Fort Worth, Texas 76107
(Address of principal executive offices)

(817) 989-7367
(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

	Large accelerated filer o		Accelerated filer o

	Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Class	Outstanding at July 31, 2008

Common Stock, par value $0.001 per share	80,181,310

TABLE OF CONTENTS

Page

PART I - FINANCIAL INFORMATION

	ITEM 1-- FINANCIAL STATEMENTS	1

	ITEM 2-- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	7

	ITEM 3-- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	14

	ITEM 4T-- CONTROLS AND PROCEDURES	14


PART II - OTHER INFORMATION

	ITEM 1-- LEGAL PROCEEDINGS	15

	ITEM 1A-- RISK FACTORS	15

	ITEM 2-- UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	15

	ITEM 3-- DEFAULTS UPON SENIOR SECURITIES	15

	ITEM 4-- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	15

	ITEM 5-- OTHER INFORMATION	15

	ITEM 6-- EXHIBITS	15

	SIGNATURES	16

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

ReoStar Energy Corporation
Consolidated Balance Sheets

	June 30, 2008 (unaudited)			March 31, 2008
ASSETS
Current Assets:
Cash	$	346,276		$	592,665
Accounts Receivable:
Oil & Gas - Related Party		1,877,381			868,406
Other - Related Party		237,156			-
Other		40,339			-
Inventory		17,958			4,748
Hedging Account		6,410			13,062
Total Current Assets		2,525,520			1,478,881

Note Receivable		1,341,062			1,355,228

Oil and Gas Properties - successful efforts method		22,321,806			17,832,931
Less Accumulated Depletion and Depreciation		(4,495,689	)		(4,139,337	)
Oil & Gas Properties (net)		17,826,117			13,693,594

Other Depreciable Assets:		1,819,174			1,641,806
Less Accumulated Depreciation		(165,738	)		(121,113	)
Other Depreciable Assets (net)		1,653,436			1,520,693

Other Related Party Receivable		80,395			80,395
Leasehold Held for Sale		1,680,813			1,680,813
Equity Method Investment		142,395			142,395
Total Assets	$	25,249,738		$	19,951,999

LIABILITIES
Current Liabilities:
Accounts Payable	$	139,699		$	103,479
Notes Payable to Related Party		500,000			324,330
Payable to Related Parties		4,300,224			1,547,136
Royalties Payable		69,879			57,485
Accrued Expenses		1,218,836			857,887
Accrued Expenses - Related Party		161,173			171,788
Short Term Notes Payable		525,000			-
Current Portion of Long-Term Debt		14,960			14,960
Total Current Liabilities		6,929,771			3,077,065

Notes Payable		1,472,999			1,647,769
Notes Payable - Related Parties		3,769,674			3,194,594
Other Related Party Payables		240,090			490,840
Less Current Portion of Notes Payable		(14,960	)		(14,960	)
Total Long-Term Debt		5,467,803			5,318,243

Deferred Tax Liability		2,584,761			2,163,183
Total Liabilities		14,982,335			10,558,491

Commitments & Contingencies:
Contingent Stock Based Compensation		268,856			214,976

Stockholders' Equity
Common Stock, $.001 par,200,000,000 shares authorized and 80,181,310 shares outstanding on June 30, 2008 and March 31, 2008		80,181			80,181
Additional Paid-In-Capital		9,590,313			9,553,346
Retained Deficit		328,053			(454,995	)
Total Stockholders' Equity		9,998,547			9,178,532
Total Liabilities & Stockholders' Equity	$	25,249,738		$	19,951,999

See Accompanying Notes to Consolidated Financial Statements

ReoStar Energy Corporation
Consolidated Statements of Operations

		Three Months Ended
		June 30, 2008 (unaudited)			June 30, 2007 (unaudited)
Revenues
Oil & Gas Sales	$	2,752,747		$	813,924
Other Income		99,416			65
		2,852,163			813,989

Costs and Expenses
Oil & Gas Lease Operating Expenses		596,033			333,521
Workover Expenses		72,425			-
Severance & Ad Valorem Taxes		154,620			48,936
Delay Rentals		-			43,615
Depletion & Depreciation		400,976			286,131
General & Administrative:
Salaries & Benefits		196,376			233,479
Legal & Professional		149,334			157,849
Other General & Administrative		132,326			59,415
Interest, net of capitalized interest of $161,576 and $141,012 for the periods ended 6/30/08 and 6/30/07, respectively		-			-
		1,702,090			1,162,946

Interest Income		61,205			23,332
Hedging Loss		(6,653	)		-

Income (Loss) from continuing operations before income taxes and discontinued operations		1,204,625			(325,625	)

Income Tax Provision		(421,618	)		113,969
Income (Loss) from Continuing Operations		783,007			(211,656	)
Income from discontinued operations, net of income taxes:
Pipeline Income		-			22,930
Gain on Sale of Pipeline		-			1,458,827
Income from discontinued operations		-			1,481,757
Net Income (Loss)	$	783,007		$	1,270,101


Basic & Diluted Loss per Common Share
Continuing Operations	$	0.01			(0.00	)
Discontinued Operations	$	-		$	0.02
	$	0.01		$	0.02

Weighted Average Common Shares Outstanding		80,181,310			76,524,026

See Accompanying Notes to Consolidated Financial Statements

ReoStar Energy Corporation
Consolidated Statements of Cash Flows

		Three Months Ended
		June 30, 2008 (unaudited)			June 30, 2007 (unaudited)
Operating Activities:
Net Income	$	783,007		$	1,270,101
Adjustments to reconcile net income to cash from operating activities:
Income Tax Expense		421,619			683,900
Depletion, Depreciation, & Amortization		400,977			286,131
Expired Leases		-			-
Stock based compensation		53,880			144,070
Joint Venture Partner Expense		-			3,072,448
Gain on Sale of Pipeline		-			(5,272,701	)
Changes in Operating Assets and Liabilities
Changes in Accrued Liabilities		47,000			37,027
Change in Inventory		(13,210	)		-
Change in Related Party Receivables/Payables		(237,156	)		25,902
Changes in Other Receivables		(40,339	)		63,389
Changes in Hedging Account		6,652			-
Changes in Royalties Payable		12,394			-
Change in Revenue Receivables		(1,008,975	)		(9,387	)
Changes in Accounts Payable		36,220			(193,131	)
Net Cash provided from operating activities		462,069			107,749
Net Cash provided from discontinued operations		-			7,164,405
Net Cash provided by operating activities and discontinued operations		462,069			7,272,154

Investing Activities:
Oil & Gas Drilling, Completing and Leasehold Acquisition Costs		(4,451,908	)		(960,681	)
Change in Capitalized Note Accretion		-			35,000
Change in Related Party Payable Related to Drilling		2,753,088			(3,826,575	)
Investment in Other Depreciable Assets		(177,368	)		(918,679	)
Note Receivable Collections		14,166			81,451
Net Cash used in investing activities		(1,862,022	)		(5,589,484	)

Financing Activities
Notes Payable (Payments) Advances		653,564			(1,950,000	)
Related Party Note Advances		500,000			-
Net Cash Received from Common Stock Subscriptions		-			6,885,353
Net Cash provided (used) from financing activities.		1,153,564			4,935,353
Net Increase (Decrease) in cash		(246,389	)		6,618,023
Cash - Beginning of the period		592,665			212,254
Cash - End of the period	$	346,276		$	6,830,277

See Accompanying Notes to Consolidated Financial Statements

ReoStar Energy Corporation
Consolidated Statements of Cash Flows
(Continued)

		Three Months Ended
		June 30, 2008 (unaudited)		June 30, 2007 (unaudited)
Supplemental Disclosure of Cash Flow Information
Cash paid during period for:
Interest	$	87,988	$	59,993

Income Taxes	$	-	$	-

Non Cash Investing and Financing Activities
Warrants Issued	$	36,967	$	-

Transfer of Accrued Interest from Notes
Payable to Accrued Liabilities	$	303,334	$	-

See Accompanying Notes to Consolidated Financial Statements

REOSTAR ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principals for interim financial information and pursuant to the rules and regulations of the United States Securities and Exchange Commission. They do not include all information and notes required by generally accepted accounting principals for complete financial statements. However, except as disclosed, there has been no material change in the information disclosed in the notes to financial statements included in the Annual Report on Form 10-KSB of ReoStar Energy Corporation for the year ended March 31, 2008. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three-month period ended June 30, 2008 are not necessarily indicative of the results that may be expected for the year ending March 31, 2009. The financial statements and notes are representations of the Company's management who are responsible for their integrity and objectivity. The Company's accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of these financial statements.

(2) CAPITAL STOCK
We have authorized capital stock of 200 million shares of common stock. There were 80,831,310 shares of common stock issued and outstanding throughout the quarter ended June 30, 2008.

On April 1, 2007, ReoStar entered into employment contracts with certain key employees. In conjunction with the employment contracts, the company approved the issuance of 700,000 shares of restricted stock. Of the 700,000 shares issued, 350,000 shares vested on March 31, 2008, and the balance of the shares will vest on March 31, 2009. For the quarters ended June 30, 2008 and June 30, 2007, Salaries and Benefits included stock related compensation costs of $48,568 and $144,070, respectively. For both periods, a liability of an equal amount was recorded as a contingent stock based compensation liability.

On April 1, 2007, ReoStar also entered into a stock option arrangement with two outside members of its board of directors. Both board members received stock options of 50,000 shares with a strike price of $1.11, one-third of which vest annually on March 31 2008, 2009, and 2010. For the quarters ended June 30, 2008 and 2007 other General & Administrative expenses included stock option costs of $5,312 and $0, respectively.

The estimated compensation expense related to the restricted stock grant and stock option grants for the following two year period is shown in the table below:

	Year Ending March 31,
		2009		2010
Restricted Stock Compensation	$	194,783	$	-
Stock Option Compensation		21,264		9,208
	$	216,047	$	9,208

(3) NOTES PAYABLE - RELATED PARTY
On June 11, 2008, the Company entered into a promissory note with a related third party. The note is due June 11, 2009 and bears interest, payable quarterly, of 13%. As additional consideration, the Company granted 100,000 stock warrants with a strike price of $0.50 per share, which was the closing price of the company's stock on June 11, 2008. The warrants expire on June 30, 2012. The Company calculated the cost of the warrant to be $36,967 using the Black-Scholes model with a volatility of 108%. The cost of the warrant was recorded as capitalized interest.

(4) SHORT TERM NOTES PAYABLE
During the quarter, the Company drew $525,000 down on the Frost Bank line of credit. The outstanding balance was $525,000 at June 30, 2008.

(5) SUBSEQUENT EVENTS
On July 25, 2008, the Board of Directors approved the 2008 Long-Term Incentive Plan whereby the Company reserved 8,000,000 shares of stock for issuance under the plan. The Board also approved the grant of 1,500,000 options to certain officers under the plan. The options have a strike price of $0.35 per share, which was the closing price on July 24, 2008, and expire on July 25, 2018. The options vest over a three year period, with the first third vesting on March 31, 2009. The options were valued at $486,483 using the Black-Scholes model with a volatility of 108%.

The following table summarizes the expected compensation expense related to the stock option grant for the next three fiscal years:

	Year Ending March 31,
		2009		2010		2011
Stock Option Compensation	$	275,885	$	151,631	$	58,967

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

CAUTIONARY STATEMENT

You should read the following discussion and analysis in conjunction with our unaudited condensed consolidated financial statements and the related notes thereto contained elsewhere in this report. The information contained in this quarterly report on Form 10-Q is not a complete description of our business or the risks associated with an investment in our common stock. We urge you to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the Securities and Exchange Commission, or SEC, including our annual report on Form 10-KSB for the year ended March 31, 2008 and subsequent reports on Form 8-K, which discuss our business in greater detail.

In this report we make, and from time to time we otherwise make, written and oral statements regarding our business and prospects, such as projections of future performance, statements of management's plans and objectives, forecasts of market trends, and other matters that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements containing the words or phrases "will likely result," "are expected to," "will continue," "is anticipated," "estimates," "projects," "believes," "expects," "anticipates," "intends," "target," "goal," "plans," "objective," "should" or similar expressions identify forward-looking statements, which may appear in documents, reports, filings with the Securities and Exchange Commission, news releases, written or oral presentations made by officers or other representatives made by us to analysts, stockholders, investors, news organizations and others, and discussions with management and other of our representatives. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995.

Our future results, including results related to forward-looking statements, involve a number of risks and uncertainties. Such risks and uncertainties include, but are not limited to, changes in local, regional, and national economic and political conditions, the effect of governmental regulation, competitive market conditions, our ability to obtain additional financing, and other risks detailed herein and from time to time in our SEC reports. No assurance can be given that the results reflected in any forward-looking statements will be achieved. Any forward-looking statement speaks only as of the date on which such statement is made.

Overview of Our Business

We are engaged in the exploration, development and acquisition of oil and gas properties, primarily located in the state of Texas. We seek to increase oil and gas reserves and production through internally generated drilling projects, coupled with complementary acquisitions.

At April 1, 2008, a certified engineering firm valued our proven reserves at $425,445,500, which reflects the present value of our future net cash flows from reserves before income taxes, discounted at 10 percent.

We own approximately 20,000 gross (16,250 net) acres of leasehold, which includes 16,000 acres of exploratory and developmental prospects as well as 4,000 acres of enhanced oil recovery prospects. We have built a multi-year inventory of drilling projects and drilling locations and currently have enough acreage to sustain several years of drilling.

Our corporate offices are located at 3880 Hulen Street, Suite 500, Fort Worth, Texas 76107. Our telephone number is (817) 989-7367.

Business Strategy

Our objective is to build shareholder value by establishing and consistently growing our production and reserves with a strong emphasis on cost control and risk mitigation. Our strategy is (1) to control operations of all our leases via our affiliated operating companies, (2) to acquire and develop leasehold in key regional resource development plays while utilizing existing infrastructure and engaging in long-term drilling and development programs, and (3) to acquire leasehold in mature fields and implement enhanced oil recovery programs.

Significant Accomplishments in the First Quarter

Barnett Shale: We completed our second "cluster" of wells in April. This cluster was comprised of six new wells that were fractured using high pressure stimulation over a three-day period. Two wells were fractured simultaneously each day. All six wells were brought online in late April and early May.

We completed our third "cluster" of wells in June. This cluster was comprised of three new wells that were fractured using high pressure stimulation over a three-day period. A fourth well not included in the cluster was also completed in June. All four wells were in flow-back at the end of the quarter, and all four were brought online in July, 2008.

During the quarter, we began re-completing four wells into the Forestburg Limestone formation, which is uphole from the Barnett interval. Two of these wells were turned over to production in June and the remaining two were turned over to production in July.

During the quarter, we also re-completed one well into a Caddo formation, which is uphole from the Barnett interval. The well was turned over to production in late June.

During the quarter, we repurchased working interests in several of our wells for a total investment of approximately $165,000. Our average working interest position in our Barnett wells is now more than 50%.

Corsicana: We began drilling the second stage of the surfactant-polymer project in the first quarter. A total of 13 new wells are in the process of being drilled, of which four wells will be injectors and nine will be producers. The expansion will continue the drilling pattern established whereby each injector has approximately four producers surrounding it (inverted five-spot drilling pattern). To date, 12 of the second stage wells have been drilled and the Company is in the process of adding pumps to facilitate the increase in volume of surfactant -polymer being injected. The Company also intends to add an alkali to its injection solution, which will help stabilize clays existent in the formation and improve the sweep efficiency of the flood.

We have acquired deeper rights on several leases and plan to drill up to five exploratory wells in the area. The first of the four exploratory wells (Pecan Gap formation) was drilled during the first quarter, but was not completed as the logs did not show enough hydrocarbons to make the well economic. The second well, a Glen Rose well, was spudded in July. We plan to drill up to three more wells in the Pecan Gap formation. We have mitigated the exploration risk associated with drilling these deeper wells by selling a 50% working interest in each of these wells to our industry partner.

Industry Environment

Oil is a global fungible commodity. The globalizations of the world's economy, the rapid development of the emerging markets, and increased commodity speculation have resulted in unprecedented commodity pricing and volatility. While natural gas is also a fungible commodity, it is more regional in nature than oil. Constant changes in regional supplies and demand have resulted in significant pricing volatility in the natural gas market as well.

We operate entirely within the United States, primarily in Texas, a mature region for the exploration and production of oil and gas. The size and frequency of new discoveries of oil and gas in the United States are declining. The trend of increasing commodity prices have placed increased upward pressure on finding and development costs.

We believe that in order for an independent oil and gas producer to be successful, the producer must either operate its leases effectively or have significant operational control over their oil and gas properties. As commodity prices fluctuate, controlling costs through operations will make the difference between making a profit and incurring a financial loss.

We believe that there remain certain areas in the continental United States that are under-explored or have not been fully exploited and developed. With the improvements of exploration, production and enhanced recovery technologies, we believe there are acquisition and production opportunities that have not been economically feasible in the past. Larger independent producers and major oil companies have ventured increasingly overseas and offshore, de-emphasizing their onshore United States assets. This movement out of mature basins with significant proven reserves has provided acquisition opportunities for well managed companies that are capable of quickly analyzing opportunities, positioned financially to quickly close an acquisition, and have the technical expertise to generate value from these assets.

We believe the acquisition market for natural gas properties has become extremely competitive as producers vie for additional production and expanded drilling opportunities. Acquisition values have reached historic highs, but we expect these values to begin to soften in the near future. We expect drilling and service costs pressures to ease slightly, but expect them to remain at a high level relative to past pricing. In addition, we expect lease operating expenses to continue to rise as producers are forced to make operational enhancements to maintain production in more mature fields.

We derive our revenues from the sale of crude oil and natural gas that is produced from our properties. Revenues are a function of the volume produced and the prevailing market price at the time of sale. The price of oil and natural gas is the primary factor affecting our revenues.

Crude oil and natural gas are commodities. The price that we receive for the crude oil and natural gas we produce is largely a function of market supply and demand. Demand for natural gas in the United States has increased dramatically over the last ten years. Demand is impacted by general economic conditions, estimates of gas in storage, weather and other seasonal condition, including hurricanes and tropical storms. Demand for crude oil has also increased over the last ten years while the increase in supply has not increased proportionately resulting in a tight market. Market conditions involving over or under supply of crude oil and natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. A substantial or extended decline in oil and gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and our ability to access capital markets.

Principal Components of Our Cost Structure

•   Direct Operating Expenses. These are day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. Such costs also include work-over repairs to our oil and gas properties not covered by insurance. To minimize and help control our costs, we acquired a work-over drilling rig and a swab rig in June of 2007, and we continue to acquire miscellaneous oil field equipment in the pursuit of operational cost control.

•   Production and Ad Valorem Taxes. These costs are primarily paid based on a percentage of market prices or at fixed rates established by federal, state or local taxing authorities.

•   Exploration Expense. The costs include geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful wells or dry holes. While our current asset mix requires a minimum of geological and geophysical costs and seismic costs, it is possible this component of our cost structure could sharply increase depending upon future property acquisitions.

•   Plugging Costs. The Corsicana field is over one hundred years old and has hundreds of abandoned well bores scattered throughout the properties. In order to properly execute our enhanced oil recovery projects, we need to plug these abandoned, worn out well bores. Since the wells are fairly shallow, we are able to cement in the entire well bore at a cost of less than $1,500 per well. To date we have plugged over 150 old well bores in the Corsicana field and will continue to maintain a schedule of plugging wells throughout the year.

•   General and Administrative Expenses. Overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of finding our working interest partners, costs of managing our production and development operations, audit and other professional fees and legal compliance are included in general and administrative expense. General and administrative expense includes stock-based compensation expense (non-cash) associated with the adoption of SFAS No. 123(R), amortization of restricted stock grants as part of employee compensation.

•   Interest. We carry minimum levels of debt, but in the future, we may finance a portion of our working capital requirements and acquisitions with borrowings under a credit facility or with longer-term public traded debt securities. As a result, interest expense could become a much more prevalent component of our cost structure.

•   Depreciation, Depletion and Amortization. As a successful efforts company, we capitalize all costs associated with our acquisition and all successful development and exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This also includes the systematic, monthly depreciation of our oilfield equipment assets.

•   Income Taxes. We are subject to state and federal income taxes but are currently not in a minimal tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs ("IDC"). We are also subject to some state income taxes. Currently, virtually all of our Federal taxes are deferred; however, at some point, we will utilize all of our net operating loss carry-forwards and we will recognize current income tax expense and continue to recognize current tax expense as long as we are generating taxable income.

Results and Analysis of Financial Condition, Cash Flows and Liquidity

During the quarter ended June 30, 2008, we sold approximately 14,630 barrels of oil compared with 6,830 barrels of oil for the quarter ended June 30, 2007, an increase of approximately 215%. The average price for oil sold during the quarter ended June 30, 2008 was $123.01 per barrel compared with the average price for the quarter ended June 30, 2007 of $61.06 per barrel, an increase of 201%.

We sold approximately 109,755 mcf of gas for the quarter ended June 30, 2008 compared with 66,815 mcf of gas for the quarter ended June 30, 2007, an increase of approximately 164%. The average price for

natural gas sold during the quarter ended June 30, 2008 was $8.68 per mcf (net of transportation, compression and CO2 charges) compared with $5.94 per mcf for the quarter ended June 30, 2008.

Oil and gas revenues for the quarter ended June 30, 2008 were $2,752,747, compared with $813,924 during the quarter ended June 30, 2007, an increase of 338%.

During the fiscal quarter ended June 30, 2008, we incurred drilling costs of approximately $4.3 million. Additionally, we repurchased working interests on several of our Barnett wells for approximately $165,000.

On June 30, 2008, we had $0.35 million in cash and total assets of $25.2 million. Debt consisted of payables to non-related parties of $3.4 million, of which, 1.5 million is long-term. We also had accounts and notes payables to related parties of $9.0 million.

During the first quarter we retained an investment banking firm to assist us in securing financing to fund our Barnett development and Corsicana re-development programs. The tightening credit market has reduced the opportunities to secure debt financing at terms that are acceptable to our Board. However, we will continue to seek to procure a senior secured credit facility, which when combined with our cash flow from production, will provide the liquidity necessary to fully implement our fiscal year 2009 capital expenditure budget. Additionally, we are considering various other financing options which may or may not be implemented during this fiscal year.

Cash Flow
Our principal sources of cash are operating cash flow, the sale of a portion of the working interest in our Barnett Shale drilling projects, and financing options, including debt and equity, that may be available to us from time to time. Our operating cash flow is highly dependent on oil and gas prices.

Based on current projections and oil and gas futures prices, the balance of the 2009 capital program is expected to be funded with internal cash flow and the proceeds of a planned credit facility.

However, there can be no assurance that we will be successful in raising capital through a credit facility, private placements or otherwise. Even if we are successful in raising capital through the sources specified, there can be no assurances that any such financing would be available in a timely manner or on terms acceptable to us and our current shareholders. Additional equity financing could be dilutive to our then existing shareholders, and any debt financing could involve restrictive covenants with respect to future capital raising activities and other financial and operational matters.

Capital Requirements
Our primary needs for cash are for exploration and development of our Barnett Shale properties, expanding the enhanced oil recovery projects in our Corsicana properties, and the acquisition of additional oil and gas properties, both in unconventional gas plays and mature fields. Our capital expenditure budget for the current fiscal year is $25 million.

Our drilling budget for the Barnett acreage is $20.5 million for fiscal year 2009. To date we have completed the seven wells that were in process at year-end and have drilled and completed three more wells in our main area of interest in Cooke County. We plan to drill up to 27 more wells by the end of the fiscal year. We will retain up to 60% working interest in the new wells. We expect to fund the drilling with the proceeds of a planned debt facility, proceeds from the sale of up to 40% working interest in each well on a turnkey basis, and cash flow from production.

We expect to re-complete at least 16 more wells in up-hole zones in fiscal year 2009 at an average cost for our working interest of approximately $50,000 per well. We expect to fund the entire re-completions out of cash flow.

We have initiated phase two of the Corsicana pilot project and we expect to expand the project during the last half of this fiscal year. Beginning in the third quarter, we plan to drill six wells per month, one-third of which will be injection wells. Funding for this phase will be achieved primarily through the planned credit facility. The total capital expenditure budget for our Corsicana project for this fiscal year is $3.4 million.

However, there can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to efficiently develop our properties and offset inherent declines in production and proved reserves.

Future Commitments
In addition to our capital expenditure program, we are committed to making cash payments in the future on two types of contracts: note agreements and operating leases. As of June 30, 2008, we have no capital leases nor have we entered into any material long-term contracts for equipment, nor do we have any off-balance sheet debt or other such unrecorded obligations.

The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at June 30, 2008. In addition to the contractual obligations listed on the table below, our balance sheet at June 30, 2008 reflects accrued interest payable on our debt of $620,666, of which $449,122 is related to the Leasehold Notes Payable, which will not be due until the associated acreage is either sold or drilled.

	Fiscal Years Ending March 31,
		2009		2010		2011		2012		Thereafter		Total
Office Lease Payments	$	150,000	$	160,000	$	-	$	-	$	-	$	310,000
Construction Loan		14,960		16,320		16,320		16,320		126,699		190,619
Notes Payable - Related Parties		-		3,518,924		-		250,750		-		3,769,674
Short Term Note Payable - Related Party		-		500,000		-		-		-		500,000
Line of Credit		525,000		-		-		-		-		525,000
Leasehold Notes Payable		-		-		-		-		1,285,100		1,285,100
	$	539,960	$	4,035,244	$	16,320	$	267,070	$	1,411,799	$	6,270,393

Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements to enhance liquidity and capital resource position, or for any other purpose.

Inflation and Changes in Prices
Our revenues, the value of our assets, and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and gas prices and the costs to produce our reserves. Oil and gas prices are subject to significant fluctuations that are beyond our ability to control or predict. In order to minimize our downside exposure to oil and gas price volatility, we will likely hedge our future production during the second quarter.

Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and accelerated during the first quarter, commodity prices for oil and gas increased significantly. The higher prices have led to increased activity in the industry and, consequently, rising costs. These costs trends have put pressure not only on our operating costs but also on our capital costs. Industry capital costs have nearly doubled during the last two years. Industry analysts expect the trend to continue during the next fiscal year.

Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end and the reported amounts of revenues and expenses during the year. We base our estimates on historical experience and various other assumptions that we believe are reasonable; however, actual results may differ.

Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material.

Successful Efforts Method of Accounting

We account for our exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

The successful efforts method of accounting can have a significant impact on the operational results reported when we enter a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

To ensure the reliability of our reserve estimates, we engage independent petroleum consultants to prepare an estimate of proved reserves. The SEC defines proved reserves as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in the depletion rates utilized by us. We cannot predict what reserve revisions may be required in future periods.

We monitor our long-lived assets recorded in property, plant and equipment in our consolidated balance sheet to ensure they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and gas reserves that will be produced from a field, the timing of future production, future production costs, future abandonment costs, and future inflation. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or gas, unfavorable adjustment to reserves, physical damage to production equipment and

facilities, a change in costs, or other changes to contracts, environmental regulations or tax laws. All of these factors must be considered when testing a property's carrying value for impairment. We cannot predict whether impairment charges may be required in the future. We are required to develop estimates of fair value to allocate purchase prices paid to acquire businesses to the assets acquired and liabilities assumed under the purchase method of accounting. The purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. We use all available information to make these fair value determinations.

Deferred Taxes

We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed many months after the close of a calendar year, tax returns are subject to audit which can take years to complete and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carry forwards and other deductible differences. We routinely evaluate deferred tax assets to determine the likelihood of realization. A valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are not likely to be realized. In determining deferred tax liabilities, accounting rules require OCI to be considered, even though such income or loss has not yet been earned.

At June 30, 2008, deferred tax liabilities exceeded deferred tax assets by $2.6 million. We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in our various income tax returns. Although we believe that we have adequately provided for all taxes, gains or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters.

Contingent Liabilities

A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of costs can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. We currently have no material accruals for contingent liabilities.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

As a "smaller reporting company" defined in Item 10(f)(1) of Regulation S-K, we are electing scaled disclosure reporting obligations and therefore are not required to provide the information requested by this item.

ITEM 4T. CONTROLS AND PROCEDURES.

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures were effective.

There have not been any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

We are currently not a party to any pending legal proceeding. From time to time, we may receive claims of and become subject to ordinary routine litigation that is incidental to the business.

ITEM 1A. RISK FACTORS.

As a "smaller reporting company" defined in Item 10(f)(1) of Regulation S-K, we are electing scaled disclosure reporting obligations and therefore are not required to provide the information requested by this item.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

Not applicable.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

Not applicable.

ITEM 5. OTHER INFORMATION.

Not applicable.

ITEM 6. EXHIBITS.

EXHIBIT NUMBER		DESCRIPTION

31.1		CEO Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2		CFO Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1		CEO Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2		CFO Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	REOSTAR ENERGY CORPORATION

August __, 2008
	By
	Scott D. Allen, Chief Financial Officer (Principal Financial Officer and duly authorized signatory)

EXHIBITS INDEX

EXHIBIT NUMBER		DESCRIPTION

31.1		CEO Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2		CFO Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1		CEO Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2		CFO Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002